Within the scope of the production of natural gas (mainly containing methane) or of liquefied natural gas, it is necessary to purify said natural gas stemming from a deposit, from a certain number of contaminants, at the first rank of which are what are called <<sour gases>>, i.e. mainly carbon dioxide (CO2) and hydrogen sulfide (H2S), with possibly mercaptans, carbonyl sulfide and/or carbon disulfide, generally in smaller amounts.
Carbon dioxide and hydrogen sulfide themselves alone may represent a significant portion of the gas mixture stemming from a natural gas deposit, typically from 3 to 70% (in molar concentration).
Many methods presently exist for de-acidifying natural gas.
A first class of methods is that of physical absorption methods, wherein the sour gases are put into contact with an absorbent solution, the transfer of the sour gases into the absorbent solution being effected by affinity. Examples of compounds which may form such suitable absorbent solutions are polyethylene glycol dimethylether (SELEXOL® method of UOP), propylene carbonate (a process from Fluor Corporation), N-methyl-pyrrolidone (PURISOL® process from Lurgi), methanol (RECTISOL® process from Lurgi) or morpholine derivatives (MORPHISORB® process from UHDE). Regeneration of the absorbent solution is carried out by successive expansions at decreasing pressures, without providing energy.
A second class of methods is that of chemical absorption processes wherein the sour gases are put into contact with an absorbent solution, the transfer of the sour gases into the absorbent solution being effected or accelerated by a chemical reaction. Examples of compounds which may form such suitable absorbent solutions are potassium carbonate (BENFIELD® process of UOP) and especially alkanolamines: notably monoethanolamine (MEA), 2-aminoethoxyethanol also known as diglycolamine (DGA), diisopropanolamine (DIPA), diethanolamine (DEA), methyldiethanolamine (MDEA), activated methyldiethanolamine and triethanolamine (TEA), as well as sterically hindered amines. Regeneration of the absorbent solution is mainly carried out in a thermal regeneration column.
Mention may also be made of a class of mixed methods with physico-chemical absorption, such as for the so-called SULFINOL® process of Shell, in which the absorbent solution is a mixture of sulfolane, water and an amine. Reference may also be made to the physico-chemical absorption process by means of a mixture of alkanolamine, water and thioalkanol which is described in document WO 2007/083012.
Conventionally, the sour gases released during the regeneration of the absorbent solution feed a Claus unit, wherein H2S is converted into sulfur but where the associated CO2 may be considered as a contaminant which causes a significant overcost in the treatment of H2S. Moreover, increasing environmental constraints tend to more and more impose that the produced CO2 not be released into the atmosphere. For example, it is desirable to be able to use the produced CO2 for improving the recovery of hydrocarbon oils (Enhanced Oil Recovery or EOR), i.e. reinjection under pressure into wells.
It is therefore desirable to have available sour gases produced in the form of two relatively pure fractions, one containing H2S and the other one CO2.
In order to perform a separation between H2S and CO2, the use of a distillation column is known. Document U.S. Pat. No. 4,293,322 proposes an H2S/CO2 distillation example by means of a third body. However, if a high degree of purity is desired for each of the two gases, it is necessary to use a piece of equipment with a large volume, costly and having a substantial consumption of energy.
An alternative method for separating sour gases is proposed in document WO 2008/107550. In this document, regeneration of the absorbent solution is carried out in several stages with decreasing pressure, the gases being recompressed and reinjected from the lower stages to the upper stages. Diversion of a portion of the gases at the stage with the lowest pressure provides an H2S-rich stream, while a CO2-rich stream is recovered at the outlet of the stage with the highest pressure. However, this method is especially effective when the ratio of the CO2 molar concentration over the H2S molar concentration is high. On the other hand, when this ratio is low, selectivity of the separation strongly decreases, i.e. the CO2 stream contains a significant proportion of H2S (of the order of 20% when the ratio of CO2/H2S concentrations is less than 1).
Therefore there exists a need for a method for purifying a gas mixture containing sour gases which allows production of a CO2 stream and of an H2S stream separately, with a high degree of purity, said method being simpler to apply and/or consuming less energy and/or being less costly than existing processes.
In particular there exists a need for such a method when the ratio of the CO2 molar concentration over the H2S molar concentration in the gas mixture to be treated is low, and is notably less than or equal to 1.